Reservoir Pressure Control

For those reservoirs which initially have reservoir fluid pressures greater than the bubble
point pressure of the hydrocarbons, it is usually desirable to maintain the flowing
bottomhole pressures of the producing wells above the bubble point pressure for a
considerable portion of the production life of the reservoir. It may be possible initially to
maintain this condition by proper selection of the choke size in the wellhead.
If the reservoir fluid pressure is sufficiently higher than the bubble point pressure of the
reservoir hydrocarbons for the well depth and hydrocarbon density, then, within fluid
property limits, the flowing bottomhole pressures can be maintained above the bubble
point pressure by manipulating the production choke size in the wellhead. This indicates,
therefore, that the reservoir pressures in the producing region surrounding the wellbore
will also be maintained above the bubble point pressure, that there will only be liquid
hydrocarbons in the reservoir and that only liquids will be produced into the wellbore at
flowing bottomhole conditions. This is normally desirable in the early production history
of a reservoir.
As produced fluid returns to the surface, however, it may reach its bubble point pressure,
so that both gas and liquid may exist at the wellhead. As the natural reservoir fluid
pressure reduces as hydrocarbons are produced, it may be necessary to inject external
fluids into the reservoir to maintain reservoir pressure. Oil production is a volume
displacement process. Idealistically, basing volumes on reservoir conditions, if, for each
reservoir barrel of oil produced, a reservoir barrel of water is injected beneath the oil zone
into the water zone, reservoir fluid pressure should maintained.
As the reservoir nears the end of its productive life, however, it will finally be desirable
to lower the flowing bottomhole pressure, through a controlled procedure, to se low a
pressure value as is feasible, to recover the maximum volumes of remaining oil and gas
(including solution gas) from the reservoir before it is depleted, as determined by
economics, and therefore abandoned,
Gas injection into a natural gas cap, which might exist above the oil zone, could also be
used for pressure maintenance. If the initial reservoir fluid pressure is greater than the
bubble point pressure of the reservoir hydrocarbons, a gas cap might created by gas
injections, even though one did not exist under original natural conditions within the
reservoir. For example, for reservoir where increased water saturations have a significant
adverse effect on permeability to the flow of oil, this gas injection process for pressure
maintenance could be initiated very early, or at the beginning of the productive life of the
reservoir.